Well installation involves drilling a wellbore into a formation where oil, gas, and other natural resources and fluids may reside. This process generally involves preparing the bottom of the hole to the required specifications, installing production tubing and making a connection between the wellbore and the formation by means of perforation, thereby allowing for the flow of natural resources to enter the wellbore adjacent the bottom of the well.
As shown in FIG. 1, well installation 100 represents the assembly of valves, spools, and fittings used for a gas well that is installed on wellhead 120. Master valve 125 controls the flow of oil or gas from the well. Well installation 100 comprises tubing 140, casing 130. Well 100 is in hydraulic communication with reservoir 110 (see FIG. 2) by means of well perforations in casing 130. The void space between tubing 140 and casing 130 which is known as the annulus, allows for fluid movement in well 100. If the amount of pressure, in pounds per square inch (psi), located in formation 110 is higher than the pressure of flow line 165 (see also FIG. 2), the natural gases and fluids 115 are pushed out of formation 110 into casing 130. When the pressure in the annulus equals the pressure of formation 110, then natural gases and accumulated fluids 115 are pushed up tubing 140 creating a tubing pressure increase. Once tubing 140 is installed, wellhead 120 is installed on top of well 100 at surface 105 (ground level) of well 100. Wellhead 120 is said to be the main point of control of a well as it is used to stop or otherwise control the flow/production from a well.
FIG. 2 depicts a well installation in communication with associated surface or production equipment installations. When a well is drilled and completed, it becomes known as a “location” or a “lease”. Surface equipment typically comprises a separator (production vessel) 180, one or more production tanks 195, 196, and a meter run via sales line 187. Separator 180 is connected to wellhead 100 by means of flow line 165. Once separator 180 is installed, it becomes the main point of control of a well.
Production fluid 185 in the form of fluids and gases is produced/pushed up from well 100 and collected in separator 180 where it undergoes a separation process. The gas portion is stored in separator 180 while the oil and water fractions are directed to oil storage tank 195 and water storage tank 196 via dump valves 190. Water storage tank 196 vents to atmosphere via vent 199.
Valve 175 (the “A valve” or sales valve) is installed at the end of separator 180 before gas flow/production enters sales line 187. An opening of valve 175 causes gases to flow into sales line 187 which serves as a meter run. The meter run is the point where the gas is measured and recorded while it is being sold into the pipeline, which can comprise miles and miles of pipe capable of collecting gases from a plurality of locations or leases for transfer to a refinery or processing plant before it is processed for sale to an end user. The meter run is also the point where line pressure is located.
Also depicted in FIG. 2 is a vent valve 275 (the “B valve”) which is installed at separator 180 to allow gas flow/production to by-pass sales line 187 and be directed to water storage tank 196. Thus, when valve 175 or valve 275 are in the closed position, flow of gases and fluids from well 100 are blocked. Alternately, when one or the other is in the open position, the flow of gases and fluids is enabled. One or both of the valves may be manual or automatic based on the type of valves and equipment being used.
Many oil and gas companies, also known as producers or operators, install a controller or a programmable logic controller (PLC) 170 near separator 180 to control and optimize a well's production volumes. Controller 170 can be pre-programmed with a well operation algorithm and is capable of managing, analyzing, and/or controlling a variety of parameters affecting a well's performance; it can be employed to operate with a variety of devices, control mechanisms and programs.
For example, controller 170 can be used to control a well's production volume by means of an opening and/or closing of valves 175, 275. There are also some controllers that have the capability of controlling a well's flow rate (or production rate) by feathering (opening and closing) valve 175. Flow control can be performed by implementing an electronic or pneumatic device such as an “I/P” device, which converts current into pneumatic pressure, that is attachable to valve 175 or valve 275 to control the pertinent valve. For example; assume a well operator does not want a well to flow over a certain production rate. The system's controller could then be programmed such that it, along with an associated I/P, would only allow valve 175 to open up enough to stay at or below the production rate that is programmed into the controller. As the energy of the well drops, the production rate also drops in the example above. The controller working in conjunction with the I/P would then allow valve 175 to open up further to try to match the production rate that is programmed into the controller. There are a wide variety of controllers and programs that are available for producers/operators to use. Usually each of these controllers or programs is specific to a certain function or operation of a well.
Throughout a well's lifetime, the well will gradually deplete in terms of production. A well's annulus pressure (the pressure of the total casing) will decrease due to the length of time the well is required to produce and because gases and fluids develop in the pipeline over the years. Since fluid and/or water are heavier than gas, the influx of fluid and/or water into the wellbore can have a serious impact on a well's production rate. If a well accumulates too much fluid and/or water in its well bore, then the weight of the fluid and/or water will push back onto the formation associated with the well, restricting the flow of gas into the wellbore. This will in turn lower the annulus pressure. When there is a lower annulus pressure and more fluid and/or water accumulation in the wellbore, it will eventually come to a point where the well can no longer produce on its own. At this stage, some form of artificial lift is implemented to purge the well of accumulated fluid. A variety of artificial lift devices and equipment are available. One of the most common is plunger lift.
In operation, a freely movable plunger 150 (see FIG. 1) is disposed within tubing 140 in well 100 and is capable of traveling vertically in tubing 140 as well 100 is cycled between shut-in and open conditions. Plunger 150 may be manufactured in many designs and configurations. A particular plunger is selected based on the relevant situation. When a well is off or “shut-in” (no production), plunger 150 drops down from lubricator 160 into tubing 140 until it reaches the end thereof. Well 100 will be shut in for an amount of time as determined by controller 170 so as to hinder the flow of formation fluid 113 from the well and thereby allow the well to build up its casing and tubing pressure to overcome line pressure and to achieve a differential pressure. As a result, formation fluid 113 accumulates in casing 130 above plunger 150 and the pressure in tubing 140 and casing 130 builds up. When a predetermined time or predetermined tubing and/or casing pressure is achieved signifying that the well is ready to produce (turn on), valve 175 is opened and formation fluid 113 is allowed to flow in an upward direction. When this happens plunger 150 begins to travel up tubing 140 from the bottom of the well, bringing fluid 115 out of the well so it may enter separator 180 and into production tanks 195, 196.
When plunger 150 arrives in wellhead 120 from the bottom of tubing 140, it may be detected by a type of magnetic switch known a plunger arrival sensor (not shown) which is housed in lubricator 160 (see FIG. 1), which may also comprise a plunger auto catching device (not shown). The sensing device may be configured to send a signal to a surface controller upon arrival of plunger 150. Conduit 165 is an initial component of the overall “sales line”. However, for purposes of convenience, conduit 165 will be referred to herein as the “flow line” and conduit 187 (see. FIG. 2) will be referred to the “sales line”.
A plunger lift system is typically operated by a controller. Not only can the controller run the plunger lift system, it can simultaneously help operate the well. Many controllers comprise preloaded systems having a variety of settings that let the controller know how to operate the well. For example, a controller can be useful for alerting the system to turn the well on and off which starts and stops the well's production. The most common of these preloadable settings are time-based settings which may comprise an “A-Open” or open mode, a “B-Open” or vent mode, a “Closed” or off mode, a “Fall-Time”or minimum off-time mode and a “Sales” or delay time mode. Where the term “A-Open” appears, it should be recognized that the term will also refer to an open mode. Similarly, a “B-Open” reference will refer to a vent mode; a “Closed” reference will refer to an off mode; “Fall-Time” means a minimum off-time mode and a “Sales” means a delay time mode.
The “A-Open” mode (see FIG. 3, Mode 200) is the mode which the system first enters when the system is signaled to begin producing the well and is usually set to have a specified time setting. In this mode, the disclosed system signals the controller to activate a valve control mechanism to open valve 175. Mode 200 designates the amount of time that the system allows for the plunger to rise to the surface of the well from the bottom of the tubing 140 string. If the plunger fails to arrive in this amount of time then the system typically enters a “B-Open” mode (Mode 600) during which the controller opens valve 275 and begins flowing the well's gases and fluids straight into tank 196. The pressure inside of tank 196 is usually lower than the line pressure (pressure in line 187) thus the force from the line on the formation associated with the well is reduced, allowing for an easier plunger travel up tubing 140.
Once the plunger arrives at lubricator 160, where it is sensed by plunger arrival sensor 161, the system will usually enter a “Sales” mode (Mode 500). When the system enters this mode, the controller closes all valves except for valve 175. The well then produces (flows) for the amount of time designated in Mode 500. When Mode 500 has ended, the system enters a “Closed” mode (Mode 800). In Mode 800, the controller communicates a signal for all valves to close which allows plunger 150 to fall to the end of tubing 140 thereby allowing the well to build up pressure to be ready for another cycle beginning with Mode 200. Some systems also have a “Fall-Time” mode (Mode 800) where the system is shut-in for a minimum amount of time to make sure that all valves are closed for a specific amount of time. The purpose of this mode is to ensure that plunger 150 has sufficient time to make it all the way to the bottom of tubing 140 to ensure an efficient plunger travel prior to the next cycle. It is contemplated that the “Fall-Time” mode (Mode 800) can be designed so it cannot be overridden.
Many plunger lift systems may also have a wide variety of pressure-based settings that are set into the methodology, including but not limited to, a “Differential Open” set point, a “High Line Pressure” set point and a “Low Line Pressure” set point. The “Differential Open” set point ensures that the system does not allow the controller to open any valves until a designated pressure differential is met. The pressure differential can be a value representing a casing pressure minus tubing pressure, or a tubing pressure minus line pressure, or a casing pressure minus line pressure. In one example; the system contemplates a “Differential Open” set point of 50 psi. If the system is operating in a casing pressure minus line pressure mode, where the casing pressure is 120 psi and the line pressure is 90 psi, the system will not allow the controller to go into Mode 200 because the casing pressure has not met the set point of 50 psi. On the other hand, if the casing pressure is 120 psi and the line pressure is 60 psi, the system would go into Mode 200 and allow the controller to open valve 175 because the designated pressure differential set point has been met.
As stated above, the system can also be implemented using pressure-based settings. A “High Line Pressure” set point is such a pressure-based setting. In the disclosed system, line pressure can be continuously monitored if desired. When the line pressure increases over the set point, triggering a “high” line pressure reading, the system signals the controller to close all valves until line pressure decreases to normal operation. The “Low Line Pressure” setting works in the same manner. As an example, the system contemplates having a “Low Line Pressure” setting of 25 psi. If the line pressure is 100 psi, for example, then the system will continue to operate normally. If the line pressure is, for example, 20 psi, the system will keep the well shut-in until line pressure rises above the designated setting of 25 psi.
Generally, controller manufactures utilize their own custom programs. Those systems are usually specific to the relevant controller and/or the type of artificial lift system that is currently in use on the well. As stated above, one of the most common types of artificial lift systems comprises a plunger lift system. Therefore, it is not uncommon that each individual well will utilize a controller and/or program that differs from that of an adjacent well. In addition, it is not uncommon that each individual well could utilize a plunger that differs from that of an adjacent well. In short, there is a high level of incongruity between wells and the associated plunger lift equipment and controllers. In addition to the above, the problem with trying to optimize a well is that it is very difficult to have a methodology that accounts for every condition that can occur on a well since many conditions are dynamic in that they are usually constantly changing.
When a well that is configured with a plunger lift/artificial lift system is being operated to its full potential, it is said to be “optimized”. Many different companies including plunger lift equipment and controller manufacturers have tried to build and design the “perfect” plunger lift operation system with a goal to optimize a well's production. Conventional systems will usually analyze a well's casing, tubing, and line pressure to determine a specific differential pressure setting to trigger turning the well on. Conventional programs will also monitor the well's production rate (or flow rate) to determine what flow rate would be best to shut the well in with, whether to make another cycle with the plunger or use another type of artificial lift system and whether to unload more fluid from the well to help optimize the well's production. There are many manufacturers with systems on the market today who claim that each can optimize a well's production. The disclosed device provides for a system and method to continuously monitor a well's production as well as its characteristics and make dynamic adjustments to its changing conditions for optimum production.
Although the disclosed system uses some of the most commonly used time-based and pressure-based options and features that are in many of the conventional programs, the system disclosed herein provides a method for applying those options and features so as to strive for continuous optimization of a well's production volume according to the well's constantly changing characteristics. The disclosed system also helps to minimize the time that is needed to optimize a well by a producer/operator. It is contemplated that the improved flow program disclosed herein can be loaded or written into any controller and can be used to retrofit existing systems.